This application claims priority from Canadian Patent Application No. 2,342,955 filed Apr. 4, 2001.
As described in U.S. Pat. No. 4,280,559 or Canadian Patent No. 1,144,064, the most common and proven method for recovering viscous hydrocarbons is by using a steam stimulation technique, commonly called the xe2x80x9chuff and puffxe2x80x9d or xe2x80x9csteam soakxe2x80x9d process. Artificial lifting methods are normally employed to maximize at each cycle the inflow of mobilized reservoir fluids as the stimulated steamed areas are depressurized and cooled. Production is terminated when it is no longer economical to further extend the production cycle and steam needs to be injected again. Cyclic steam stimulation xe2x80x9cCSSxe2x80x9d cycles can be repeated many times until oil production is insufficient to remain economical due to decreasing thermal efficiency. After several decades, the fact remains that CSS remains the only in situ process, which has been proven to be effective on a commercial basis in Canadian tar sands. Therefore, there is still a strong need to further develop methods that can increase the productivity of CSS wells in order to decrease lifting costs associated to CSS steam generation and water recycle requirements. These costs usually become prohibitive at some limited level of recovery in so-called mature CSS areas. The change-over from cyclic to continuous steaming operations or infilling additional wells has not yet been proven commercially viable and our invention therefore aims at specifically improving performance of base CSS operations without having to modify the configuration and/or functionality of existing wells in the field. Enhancement of the CSS process will allow us to extend its useful life and increase the ultimate recovery of original oil in place.
The concept of using light hydrocarbons as steam additives is not new, as evidenced by several patents granted in the late seventies and early eighties. Various methods have been proposed to use hydrocarbon solvents in combination with steam to improve heavy oil recoveries in a wide range of reservoir conditions and well configurations. Of particular relevance to our CSS target application, Best had described in U.S. Pat. No. 4,280,559, an improved steam stimulation process. After one or more steam stimulation cycles to establish substantial fluid mobility around each CSS well, Best proposed to inject a slug of an appropriate hydrocarbon solvent prior to subsequent CSS cycles. He specified the hydrocarbon solvent as a hydrocarbon fraction containing a low concentration of low molecular weight paraffinic hydrocarbons, which has a boiling point range for the most part less than the steam injection temperature and greater than the initial reservoir temperature. The boiling point range he specified thus excluded the use of butane and lighter hydrocarbons; which typically boil below initial reservoir temperature (13xc2x0 C. in Cold Lake Clearwater formation where the largest CSS commercial operations are developed). As shown in FIG. 3 of Best""s original patent, the use of coker butanerich gas had shown no beneficial effects in his experimental tests. In another preferred embodiment of his process, Best had professed to inject a quantity of solvent between about 5 to about 15 volume percent of the cumulative oil volume produced from previous CSS cycles at a well. His range more or less overlaps with the expected range of concentrations expected for applying Liquid Addition to Steam for Enhancing Recovery of Cyclic Steam Stimulation, or (LASER-CSS.)
Subsequent to Best, Allen et al. described in U.S. Pat. No. 4,450,913 a superheated solvent method including from butane to octane for recovering viscous petroleum. However, there was no provision for injection of steam into the formation as described in their supporting experimental work with Utah tar sand cores. In U.S Pat. No. 4,498,537, Cook describes a producing well stimulation methodxe2x80x94a combination of thermal and solvent. However his method uses an in situ combustion process to generate heat and carbon dioxide as a solvent. No direct injection of steam was embodied in his process.
U.S. Pat. No. 4,127,170 (Redford) relates to a viscous oil recovery method employing steam and hydrocarbons. The method is essentially continuous with injection pressures being adjusted to control production rates.
U.S. Pat. No. 4,166,503 (Hall et al.) relates to a high vertical conformance steam drive oil recovery method employing infill wells as well as injection and production wells. The method employs steam and hydrocarbons but appears primarily to address problems relating to steam channeling and overriding.
In 1985, Islip and Shuh described in U.S. Pat. No. 4,513,819 a cyclic solvent assisted steam injection process for recovery of viscous oil. On the basis of two-dimensional radial numerical simulations they propose a cyclic steam/solvent drive process between injection and producing wells. The process they represented requires a fluid communication zone located in the bottom of the formation between injection and producing wells with the latter completed near the top of the formation. The ratio of solvent to steam is set at between 2 and 10 volume percent to enhance the base cycle steam drive process. The major difference with our LASER-CSS disclosure is that we continue to operate in a cyclic steam stimulation mode using hydrocarbon additives at each CSS well, without forcing injected fluids to be transferred and driven towards adjacent wells. As described in their simulations, Islip and Shuh""s process requires the presence of a bottom water zone to ensure that effective communication remains in the lower part of the formation.
Subsequently in 1987, Vogel described in U.S. Pat. No. 4,697,642 a gravity thermal miscible displacement process. In contrast to Islip and Shuh, a steam and solvent vapor mixture is injected into the top of the formation to establish a vapor zone across the top of the formation. The solvent vapors as they condense and go in solution with the viscous hydrocarbons, further reduce the viscosity of the viscous hydrocarbon, thereby enabling the native hydrocarbons to drain faster under the force of gravity into an adjacent well completed at the bottom of the reservoir. Vogel""s process is essentially operated as a continuous injection process, not in a cyclic mode. A potential problem with his approach is rapid breakthrough of injected solvent vapors at adjacent producing wells as these solvent vapors traverse across the overriding steam blanket. This continuous by-passing makes it difficult to control the storage and effectiveness of hydrocarbon steam additives to contact and dissolve into a significant part of the heavy oil or bitumen residing between communicating wells.
A decade later in 1997, Richardson et al. in 1997 described in U.S. Pat. No. 5,685,371 another hydrocarbon assisted thermal recovery method. The authors point out that the action of low molecular weight additives into a reservoir undergoing steamflooding has been marginal in improving steamflood oil recovery. They suggest that this is probably due to the fact that xe2x80x9cmost of the low molecular weight additive moves quickly through the formation and is produced with the vapor phasexe2x80x9d. This bypassing of light hydrocarbons will be particularly severe in continuous steamflood operations where preferential channeling towards specific wells invariably develops inside a formation. Richardson instead proposes to use heavier hydrocarbons to counteract this by-passing, as these heavier hydrocarbons will condense more readily while in transit between wells. Therefore, he recommends using hydrocarbons having a boiling point higher than water (e.g. C7+ or selected cuts from refinery operations). With LASER-CSS our intention is to use natural condensate streams, commonly referred to as diluents, as solvent additives of choice for steam. This is because such diluent streams are already available on site in Alberta to facilitate transportation by pipeline of produced heavy oils. Accordingly, the fraction of diluent reproduced with LASER-CSS will decrease the blending requirements required on the surface to meet regulation requirements for pipeline transportation, as well as facilitate the dehydration step of produced emulsions.
Aside from all the above-related solvent addition to steam prior art inventions, in 1982 Butler described in U.S. Pat. No. 4,344,485 a method for continuously producing viscous hydrocarbons by gravity drainage while injecting heated fluids like steam. Since then the method has often been referred by those skilled in the art as Steam-Assisted-Gravity-Drainage or SAGD. However, Conventional CSS methods remain the most successful and proven for recovering viscous bitumen hydrocarbons. Batycky published an assessment of in situ oil sands recovery processes in 1997 (Journal of Canadian Petroleum Technology, Volume 36, p.15-19, October 1997 ). In a section on CSS at Cold Lake, he described how development of field steaming strategies with maximum overlap and alignment between rows of wells have been used to control the movement of fluids across the field. Proposed enhancement of CSS with LASER-CSS is intended to conform with the best CSS injection practices. Similarly, during production cycles, bottomhole rod pump operations are adjusted to maximize produced inflow volumes of mobilized reservoir fluids as the reservoir surrounding each well is blown down, while at the same time avoiding inefficient excessive venting of free steam and other vapors. Our intention is to operate the LASER-CSS process using the same bottom-hole production equipment that is used in our conventional CSS operations.
As the CSS process matures across its cycles, its efficiency also declines and only a limited fraction of bitumen is recovered. Therefore, there is a continuing need for an improved thermal process for a more effective recovery of viscous hydrocarbons from subterranean formations such as in Canadian tar sands deposits.
An improved steam stimulation recovery process referred to as Liquid Addition to Steam for Enhancing Recovery of Cyclic Steam Stimulation, or LASER-CSS is disclosed, which is based on the principle of combining solvent viscosity reduction and thermal viscosity reduction effects to enhance the effectiveness of cyclic stimulation processes. In practice, this means that at least one steam stimulation cycle is desirable, and generally several cycles will be performed to use and recover the solvent most effectively. However, instead of injecting a slug of an appropriate hydrocarbon solvent into the formation prior to the steam, LASER-CSS looks more specifically at co-injecting the solvent with the injected steam during steam injection cycles into each well. Also, the preferred type of solvent in LASER-CSS consists of on-site commercial diluent already used for transportation of thermally produced bitumen. Commercially available diluent streams have a boiling point range for the most part less than the steam injection temperature and greater than the initial reservoir temperature. We have found that in a three-dimensional CSS physical model after having conducted several conventional CSS cycles, the addition of diluent into the steam greatly improves the efficiency and productivity of subsequent LASER-CSS compared to straight CSS cycles.
The invention provides a process for recovering viscous oil from a subterranean deposit, which process comprises: (a) injecting steam into said deposit and then; (b) shutting said steam in said deposit to lower viscosity of at least a portion of said viscous oil and then; (c) recovering oil of lowered viscosity from said deposit; and (d) repeating steps (a) to (c) to form a steam chamber in said deposit and then; (e) co-injecting steam and a hydrocarbon solvent into said deposit and then; (f) shutting said steam and said hydrocarbon solvent in said deposit to lower viscosity of at least a portion of said viscous oil and then; (g) recovering oil of lowered viscosity from said deposit; and (g) repeating steps (e) to (g) as required.
In a second embodiment, the invention provides a process for recovering viscous oil from a subterranean deposit penetrated by at least two wells, which process comprises (a) injecting steam into said deposit through a first well and then; (b) shutting said steam in said deposit to lower viscosity of at least a portion of said viscous oil and then; (c) repeating steps (a) and (b) to form a steam chamber in said deposit and then; (d) recovering oil of lowered viscosity from said deposit through a second well and then; (e) co-injecting steam and a hydrocarbon solvent into said deposit through the first well and then; (f) shutting said steam and said hydrocarbon solvent in said deposit to lower viscosity of at least a portion of said viscous oil and then; (g) recovering oil of lowered viscosity from said deposit through the second well; and (h) optionally, repeating steps (e) to (g).
The invention may additionally comprise cyclically alternating between (i) injecting steam or steam and a hydrocarbon solvent into a first adjacent well while holding a second adjacent well shut and (ii) shutting said steam or steam and a hydrocarbon solvent into said first adjacent well and opening and recovering viscous oil from said second adjacent well.
The invention also may additionally comprise cyclically alternating between (i) co-injecting steam and a hydrocarbon solvent into a first adjacent well while holding a second adjacent well shut and (ii) shutting said steam or steam and a hydrocarbon solvent into said first adjacent well and opening and recovering viscous oil from said second adjacent well.
In preferred embodiments, at least one of the wells is upstanding with respect to the ground and may indeed be substantially vertical. In alternative embodiments, the well may be slanted with respect to the ground or even substantially horizontal.
In further preferred embodiments, the solvent is a hydrocarbon diluent suitable for transporting bitumen. The solvent may have an average initial boiling point close to the boiling point of pentane (36xc2x0 C.) or hexane (69xc2x0 C.) though the average boiling point (defined further below) may change with re-use as the mix changes (some of the solvent originating among the recovered viscous oil fractions). Preferably more than 50% by weight of the solvent has an average boiling point lower than the boiling point of decane (174xc2x0 C.). It is more preferred that more than 75% by weight, more especially more than 80% by weight, and particularly more than 90% by weight of the solvent has an average boiling point between the boiling point of pentane and the boiling point of decane.
In further preferred embodiments, the solvent has an average boiling point close to the boiling point of hexane (69xc2x0 C.) or heptane (98xc2x0 C.), or even water (100xc2x0 C.).
In additional preferred embodiments, more than 50% by weight of the solvent (more particularly more than 75% or 80% by weight and especially more than 90% by weight) has a boiling point between the boiling points of pentane and decane. In other preferred embodiments, more than 50% by weight of the solvent has a boiling point between the boiling points of hexane (69xc2x0 C.) and nonane (151xc2x0 C.), particularly preferably between the boiling points of heptane (98xc2x0 C.) and octane (126xc2x0 C.).